I. Field of the Invention
The present invention relates to methods for treating remediated flowback water with a fluid treatment system comprising at least one friction reducing agent; and at least one scale formation inhibiting agent and/or at least one iron precipitation control agent for reuse as fracturing fluid for a well drilling operation.
II. Technical Considerations
Once a natural gas well has been drilled, the final stage is to connect the wellbore and the subterranean formation to permit extraction of the gas contained therein. Generally, this connection is made by creating perforations in the well casing or liner using explosive charges. Sometimes, after the well is completed, further stimulation is necessary to enhance productivity.
One important stimulation technique is fracturing, which involves creating and extending fractures from the perforation tunnels deeper into the formation to increase the surface area for formation fluids to flow into the well, as well as extending past any possible damage near the wellbore. This may be done by injecting fluids or foams at high pressure (hydraulic fracturing). These fluids or foams may contain granular material, commonly referred to as proppants.
In a hydraulic fracturing process, aqueous fracturing fluid is injected under pressure into the bore hole. The pressure drives the fluid into cracks, fissures and fractures in the formation, forcing such openings to become larger and propagate. Proppant material contained therein wedges into the expanded cracks, fissures and fractures to help hold them open when the pressure is reduced and to provide improved formation permeability. The injected fracturing fluid mixes with groundwater, gas, and other materials present in the subterranean environment.
When the pressure is removed, this fluid mixture flows back to the surface and gas is extracted therefrom. The fracturing fluid mixture after extraction (recovered fracturing fluid and produced water) is “flowback water” or “backflow water”, i.e., the recovered water and fracturing fluid which flow back from oil or gas well drilling fracturing operation. This flowback water typically can be anywhere from 10-60% percent of the volume of fluid that is injected into the well, and it flows back over a period of several days to several weeks or longer after fracturing. A significant amount of fracturing fluid can remain in the formation. At a certain point there is a transition between primarily recovering fracturing fluid to that of produced water. A typical fracturing job on a Marcellus shale formation could require 20,000 barrels to 150,000 barrels of fracturing fluid, depending upon the number of stages pumped. For a project pumping 40,000 barrels of fracturing fluid, the load recovery could be 50% or 20,000 barrels of flowback. After the initial several week post-fracturing recovery, an additional 10,000 to 30,000 barrels of produced water may flow for up to two years.
Flowback water generally contains high salinity and total dissolved solids (TDS). Flowback waters consist of water, the fracturing chemicals that were injected into the well, as well as any contaminants that are present in the rock formation water. In addition to natural salinity of water in the formation, any fresh water that is injected into the well during the fracturing process will tend to dissolve salts in the formation, thus increasing the salinity of the flowback water.
As used herein, “flowback water” can have a Total Dissolved Solids (TDS) content of greater than about 10,000 milligrams per liter (mg/L) dissolved solids in the flowback water, a ferrous iron (Fe+2) ion concentration of less than about 100 mg/L ferrous iron ion in the flowback water, a barium ion (Ba+2) concentration of less than about 500 mg/L barium ion in the flowback water, and a calcium ion (Ca=) concentration of at least about 1,000 mg/L calcium ion in the flowback water.
It is desirable to reuse the flowback water in a subsequent fracturing operation. However, carbonate and sulfate ions present in flowback water can form precipitates such as calcium carbonate, calcium sulfate, barium sulfate and iron carbonate within the underground fracture network and cause scale accumulation in perforations or fissures in the fractured rock.
The presence of iron provides a significant and complex problem in well stimulation operations. Iron in the ferric state can form iron complexes that can block flow pathways and inhibit the flow of gas and/or oil therethrough. Also, iron can impair the performance of fracturing fluid components, such as the friction reducing additive.
In oil and gas wells, air can be introduced into water present in the underground formation through the borehole or from comingling of underground water with air-saturated water which has been pumped from the surface into the well. Ground or well water typically exists in a reducing environment. As a result, iron in ground or well water typically is present as the ferrous ion (Fe+2) species. The ferrous iron can originate from many sources, such as the minerals contained within stratigraphic formations surrounding the water or from additives added to the water during oil or gas well drilling or fracturing operations. Exposure to air (oxygen) or other oxidants (chlorine, bromine, stabilized bromine, etc.) causes ferrous ions to be oxidized to insoluble ferric (Fe+3) ion complexes. Ferric ion complexes, such as hydrated ferric oxides (Fe2O3.nH2O), are much less soluble than ferrous iron, and once formed can readily precipitate. The accumulation of these solids can block pores and flow pathways (or fracture conductivity) in the oil or gas well formation, thus causing permeability impairment with an associated decline in oil or gas flow. While not intending to be bound by any theory, it is believed that when iron is present in soluble or dispersed form, it is less likely to block the flow pathways, thus enhancing production potential of the well.
The formation or precipitation of iron oxides can be inhibited by stabilization of the ferrous ion, and/or suspension or dispersion of the iron oxide(s). Stabilization is the process by which polymers: (1) form stable complexes with dissolved iron, thus preventing the formation of insoluble Fe2O3.nH2O and (2) absorb onto the surface of particulates that are forming, thereby greatly restricting particle growth and thus allowing the particles to remain suspended. In contrast, dispersion is the process by which pre-formed iron oxide (Fe2O3) particles are prevented from settling by the action of a polymer. Dispersants are generally negatively charged, low molecular weight polymers. Likewise, the surface charge of iron oxide particles is negative. The repulsion between the negatively charged particle surface and negatively charged polymers prevents the particles from agglomerating and settling.
To prevent clogging of the flow pathways in oil and gas well formations, chelating agents have been used. Citric acid, ethylenediaminetetraacetic acid (EDTA) and nitriloacetic acid (NTA) are common iron chelating agents used for iron control in fracturing fluid design. Chelating agents function on a stoichiometric basis, i.e., one mole of chelating agent is needed per mole of iron. Additional chelating agent is needed to drive the reaction, with the dose depending on the conditional stability constant (K=[complex]/[metal][chelating agent], K being a function of pH). Thus, high doses of chelating agent are needed. The large dose requirement of citric acid results in pH depression, which in turn can negatively impact some friction reducing additives, such as polyacrylamide-based products. While sulfonated polymers have been used to disperse pre-formed ferric iron particulates and/or to stabilize low levels (≦10 mg/L) of ferrous ions in cooling water applications, they have not been used in oil and gas well water to stabilize the high levels of ferrous ions and/or ferric oxide particulates which can exceed 20 mg/L.
In another aspect of the stimulation process, during the hydraulic fracturing operation fluid is pumped at high velocity and high pressure drops are encountered, resulting in large energy losses. Pressures at the surface of the well of 3,000 to 15,000 psi are often required to overcome the frictional losses and fracture initiation pressure. It is well known that energy is lost due to frictional forces encountered during the movement of liquid through a pipe, tubing or conduit. The energy loss is reflected in a progressive drop in pressure measured along the path between the inlet and discharge point. Factors such as fluid velocity, pipe diameter, pipe length, interior surface roughness, fluid density, and fluid viscosity impact the pressure drop, also known as differential pressure.
Well-known laws of fluid dynamics correlate pressure drop as being proportional to fluid velocity. The Reynolds' number (Re) is a dimensionless number that gives a measure of the ratio of inertial forces (ρV2L2) to viscous forces (μVL), and is used to describe different flow regimes, such as laminar or turbulent flow: laminar flow occurs at low Reynolds numbers, where viscous forces are dominant, and is characterized by smooth, constant fluid motion, while turbulent flow occurs at high Reynolds numbers and is dominated by inertial forces, which tend to produce random eddies, vortices and other flow instabilities. As fluid velocity increases, the conditions change from laminar to transitional to turbulent flow. Under laminar conditions flow is smooth and energy loss is minimal, while under turbulent conditions random impurities and other flow instabilities contribute to greater energy loss. Generally, turbulent flow exists when the Reynolds' number of a fluid is >5,000. For the most part, hydraulic fracturing operations occur in the turbulent flow regime. Therefore, reducing energy loss results in significant economic and safety incentives based on lower operating pressures, less equipment fatigue, lower horsepower demand and less capital for equipment.
It is well known that small amounts of high molecular weight polymers can be very effective in reducing friction loss of flowing aqueous fluids. Slickwater applications have been effectively applied in the hydraulic fracturing of Barnett Shale and other unconventional gas shale applications. Certain metal ions, such as ferrous iron, are known to degrade polyacrylamide polymers. The exact mechanism for this degradation is not completely understood but is thought to proceed by a free radical mechanism. Since oxygen is known to accelerate degradation, it seems plausible that an oxygen-anion radical is formed when a metal ion is oxidized. The highly reactive oxygen-anion radical then can attack the polymer chain, scission the polymer backbone and result in performance deterioration.
Often, the combination of alkalinity, calcium hardness, total dissolved solids (TDS), pH, and temperature of water creates a positive value LSI, indicative of water with potential to precipitate scale forming salts. Specifically, hardness in the form of calcium and magnesium ions combines with anions, such as carbonate and sulfate, to form a solid. This solid material will form scale and may combine with other chemicals in the water. The higher the hardness, the faster scale will form. As the various reaction products precipitate on surfaces of the water carrying system, they form scale or deposits. This accumulation prevents effective heat transfer, interferes with fluid flow, facilitates corrosive processes, and harbors bacteria. This scale is an expensive problem causing delays and shutdowns for cleaning and removal.
Also, carbonate and sulfate ions can be present in flowback water from fracturing operations. The fracturing fluid in the downhole environment can release soluble salts from the formation that can combine with the frac fluid and form precipitates such as calcium carbonate, calcium sulfate, barium sulfate, strontium sulfate, and iron carbonate within the underground fracture network and cause scale accumulation in perforations or fissures in the fractured rock.
Solubility product concentrations are exceeded for various reasons, such as partial evaporation of the water phase, an increase in pH, or temperature, and the introduction of additional ions, which form insoluble compounds with the ions already present in solution. For example, mine pool water that is pumped to the surface undergoes degassing of CO2 followed by an increase in solution pH. The corresponding Langelier Scale Index (LSI) shifts from a negative value (corrosive) to a positive value (scaling). LSI is often used by water treatment specialists to describe the scaling potential of water for applications.
More specifically, the LSI is an equilibrium model derived from the theoretical concept of saturation and provides an indicator of the degree of saturation of water with respect to calcium carbonate. It can be shown that the LSI approximates the base 10 logarithm of the calcite saturation level. The Langelier saturation level approaches the concept of saturation using pH as a main variable. The LSI can be interpreted as the pH change required to bring water to equilibrium. In order to calculate the LSI, it is necessary to know the alkalinity (mg/L as CaCO3), the calcium hardness (mg/L Ca2+ as CaCO3), the total dissolved solids (mg/L), the actual pH, and the temperature of the water (° C.).
There is a long-felt need in the art for treatments for flowback water for inhibiting the formation and/or precipitation of ferric oxide, calcium carbonate and barium sulfate particulates to permit reuse of the flowback water in subsequent fracturing operations.